Noble metal catalysts and processes for reforming of methane and other hydrocarbons

ABSTRACT

Processes for converting methane and/or other hydrocarbons to synthesis gas (i.e., a gaseous mixture comprising H 2  and CO) are disclosed, in which at least a portion of the hydrocarbon(s) is reacted with CO 2 . At least a second portion of the methane may be reacted with H 2 O (steam), thereby improving overall thermodynamics of the process, in terms of reducing endothermicity (ΔH) and the required energy input, compared to “pure” dry reforming in which no H 2 O is present. Catalysts for such processes advantageously possess high activity and thereby can achieve significant levels of methane conversion at temperatures below those used conventionally under comparable conditions. These catalysts also exhibit high sulfur tolerance, in addition to reduced rates of carbon (coke) formation, even in the processing (reforming) of heavier (e.g., naphtha boiling-range or jet fuel boiling-range) hydrocarbons. The robustness of the catalyst translates to high operating stability. A representative catalyst comprises 1 wt-% Pt and 1 wt-% Rh as noble metals, on a cerium oxide support.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

This invention was made with government support under U.S. Department ofEnergy Award DE-EE-0007009. The government has certain rights in theinvention.

FIELD OF THE INVENTION

Aspects of the invention relate to catalysts and processes for thereforming of methane and/or other hydrocarbons, and more particularly tothe reaction of such hydrocarbon(s) with CO₂ as an oxidant, or with bothCO₂ and H₂O as a combination of oxidants, in the presence of a noblemetal-containing catalyst, to produce a synthesis gas product comprisingH₂ and CO.

DESCRIPTION OF RELATED ART

The ongoing search for alternatives to crude oil, for the production ofhydrocarbon fuels is increasingly driven by a number of factors. Theseinclude diminishing petroleum reserves, higher anticipated energydemands, and heightened concerns over greenhouse gas (GHG) emissionsfrom sources of non-renewable carbon. In view of its abundance innatural gas reserves, as well as in gas streams obtained from biologicalsources (biogas), methane has become the focus of a number of possibleroutes for providing liquid hydrocarbons. A key commercial process forconverting methane into fuels involves a first conversion step toproduce synthesis gas (syngas), followed by a second, downstreamFischer-Tropsch (FT) synthesis step. In this second step, the synthesisgas containing a mixture of hydrogen (H₂) and carbon monoxide (CO) issubjected to successive cleavage of C—O bonds and formation of C—C bondswith the incorporation of hydrogen. This mechanism provides for theformation of hydrocarbons, and particularly straight-chain alkanes, witha distribution of molecular weights that can be controlled to someextent by varying the FT reaction conditions and catalyst properties.Such properties include pore size and other characteristics of thesupport material. The choice of catalyst can impact FT product yields inother respects. For example, iron-based FT catalysts tend to producemore oxygenates, whereas ruthenium as the active metal tends to produceexclusively paraffins.

With respect to the first conversion step, upstream of FT, knownprocesses for the production of syngas from methane include partialoxidation reforming and autothermal reforming (ATR), based on theexothermic oxidation of methane with oxygen. Steam methane reforming(SMR), in contrast, uses steam as the oxidizing agent, such that thethermodynamics are significantly different, not only because theproduction of steam itself can require an energy investment, but alsobecause reactions involving methane and water are endothermic. Morerecently, it has also been proposed to use carbon dioxide (CO₂) as theoxidizing agent for methane, such that the desired syngas is formed bythe reaction of carbon in its most oxidized form with carbon in its mostreduced form, according to:

CH₄+CO₂→2CO+2H₂.

This reaction has been termed the “dry reforming” of methane, andbecause it is highly endothermic, thermodynamics for the dry reformingof methane are less favorable compared to ATR or even SMR. However, thestoichiometric consumption of one mole of carbon dioxide per mole ofmethane has the potential to reduce the overall carbon footprint ofliquid fuel production, providing a “greener” consumption of methane.This CO₂ consumption rate per mole of feed increases in the case ofreforming higher hydrocarbons (e.g., C₂-C₆ paraffins), which may bedesired, for example, if hydrogen production (e.g., for refineryprocesses) is the objective. In any event, the thermodynamic barriernonetheless remains a major challenge and relates to the fact that CO₂is completely oxidized and very stable, such that significant energy isneeded for its activation as an oxidant. In view of this, a number ofcatalyst systems have been investigated for overcoming activation energybarrier for the dry reforming of methane, and these are summarized, forexample, in a review by Lavoie (FRONTIERS IN CHEMISTRY (November 2014),Vol. 2 (81): 1-17), identifying heterogeneous catalyst systems as beingthe most popular in terms of catalytic approaches for carrying out thisreaction.

Whereas nickel-based catalysts have shown effectiveness in terms oflowering the activation energy for the above dry reforming reaction, ahigh rate of carbon deposition (coking) of these catalysts has also beenreported in Lavoie. The undesired conversion of methane to elementalcarbon can proceed through methane cracking (CH₄→C+2H₂) or the Boudouardreaction (2CO→C+CO₂) at the reaction temperatures typically required forthe dry reforming of methane. Therefore, although this reaction has beeninvestigated as a promising route for syngas production, thecommercialization of this technology, unlike other reformingtechnologies such as ATR and SMR, remains unrealized. This is due inlarge part to high rates of carbon formation and the accompanyingdeactivation of catalysts through coking, as encountered in the use ofdry reforming catalyst systems that operate under conditions proposed todate. Finally, whereas other conventional reforming technologies haveproven to be economically viable, these processes, and particularly SMR,are known to require significant upstream capital and operating expensesfor the removal of sulfur and other poisons of the catalysts used.Otherwise, commercially acceptable periods of operation from a givencatalyst loading cannot be achieved. Satisfactory solutions to these andother problems relating to the conventional reforming of hydrocarbonsfor the production of syngas and/or hydrogen have been sought but notachieved.

SUMMARY OF THE INVENTION

Aspects of the invention are associated with the discovery of catalystsand processes for converting methane and/or other hydrocarbons tosynthesis gas (i.e., a gaseous mixture comprising H₂ and CO) by reactingat least a portion of such hydrocarbon(s) with CO₂. Preferably,according to a CO₂-steam reforming reaction, at least a second portionof the hydrocarbon(s) (e.g., comprising the same hydrocarbon(s) as inthe first portion) is reacted with H₂O (steam), thereby improvingoverall thermodynamics of the process, in terms of reducingendothermicity (ΔH) and the required energy input, compared to “pure”dry reforming in which no H₂O is present. Representative catalystsadvantageously possess high activity and thereby can achieve significantlevels of hydrocarbon (e.g., methane) conversion at temperatures belowthose used conventionally for dry reforming. These high activity levels,optionally in conjunction with using H₂O to provide at least a portionof the oxidant, contribute to an overall operating environment wherebycoke formation is reduced and useful catalyst life may be significantlyextended.

Yet further important advantages reside in the sulfur tolerance ofcatalysts described herein, whereby a pretreatment of amethane-containing feedstock (e.g., natural gas), or otherhydrocarbon-containing feedstock, to reduce the concentration of H2S andother sulfur-bearing contaminants is not required according to preferredembodiments, or is at least not as rigorous as in conventional reformingtechnologies. Also, to the extent that downstream sulfur removal may bedesirable, such as prior to an FT conversion step, this may be greatlysimplified, considering that all or at least a substantial portion ofsulfur-bearing contaminants other than H₂S, such as mercaptans, can beoxidized in a dry reforming or CO₂-steam reforming reaction as describedherein to SO₂, thereby rendering standard acid gas treatment (e.g.,scrubbing) as a suitable and relatively simple option for suchdownstream sulfur removal,

Overall, improvements associated with the processes and catalystsdescribed herein are of commercial significance in terms of renderingdry reforming processes, or otherwise CO₂ and steam reforming (i.e.,“CO₂-steam reforming”) processes, as an economically viable alternativeto conventional technologies such as autothermal reforming (ATR) andsteam methane reforming (SMR) Moreover, the synthesis gas according tothese processes may be produced with a favorable molar H₂:CO ratio(e.g., about 2:1) for downstream processing via the Fischer-Tropsch (FT)reaction, or at least with a molar ratio that may be readily adjusted toachieve such favorable values.

These and other embodiments, aspects, and advantages relating to thepresent invention are apparent from the following Detailed Description.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete understanding of the exemplary embodiments of thepresent invention and the advantages thereof may be acquired byreferring to the following description in consideration of theaccompanying figures, in which the same reference numbers are used toidentify the same features.

FIGS. 1A and 1B depict flowschemes that illustrate representative dryreforming and CO₂-steam reforming processes as described herein.

FIG. 2 illustrates the high activity, in terms of methane conversion, ofcatalysts as described herein.

FIG. 3 illustrates the relationship between the molar H₂:CO ratio of thesynthesis gas product and the molar H₂O/CO₂ ratio of the gaseous mixturein the reactor (as a combined feed) at different reaction temperatures,in the case of representative CO₂-steam reforming processes.

FIGS. 4 and 5 illustrate the long term operational stability ofcatalysts as described herein, in a CO₂-steam reforming process over anextended operating period.

The figures should be understood to present illustrations of processesand certain associated results and parameters and/or principlesinvolved. In order to facilitate explanation and understanding, FIGS. 1Aand 1B provide a simplified overview, with the understanding that thesefigures and elements shown are not necessarily drawn to scale. Valves,instrumentation, and other equipment and systems not essential to theunderstanding of the various aspects of the invention are not shown. Asis readily apparent to one of skill in the art having knowledge of thepresent disclosure, processes for converting hydrocarbons such asmethane, by dry reforming or CO₂-steam reforming, will haveconfigurations and elements determined, in part, by their specific use.

DETAILED DESCRIPTION

The expressions “wt-%” and “mol-%,” are used herein to designate weightpercentages and molar percentages, respectively. The expressions“wt-ppm” and “mol-ppm” designate weight and molar parts per million,respectively. For ideal gases, “mol-%” and “mol-ppm” are equal topercentages by volume and parts per million by volume, respectively.

The term “gaseous mixture” refers to the mixture comprising at least ahydrocarbon such as methane and also comprising CO₂ as an oxidant, whichis subjected to dry reforming or CO₂-steam reforming (if water is alsopresent in the gaseous mixture) by contact with a catalyst as describedherein. The term “gaseous mixture” refers generally to this mixturebeing completely or at least predominantly in the gas phase underconditions used for dry reforming or CO₂-steam reforming, including thetemperatures and pressures described herein as being suitable for thesereactions. The term “gaseous mixture” does not preclude the presence ofcompounds in this mixture that, like water, are liquid under conditionsof ambient temperature and pressure. Such compounds can includehydrocarbons found in liquid fuels including naphtha and jet fuels, forexample C₆-C₁₆ hydrocarbons.

Embodiments of the invention are directed to a process for producing asynthesis gas product (syngas), the process comprising contacting agaseous mixture comprising (i) methane and/or other hydrocarbon(s)(e.g., any of CH₄, C₂H₆, C₂H₄, C₃H₈, C₃H₆, C₄H₁₀, C₄H₈, C₅H₁₂, C₅H₁₀,higher molecular weight hydrocarbons, and mixtures thereof) and (ii)CO₂, with a catalyst comprising at least one (e.g., two, or more thantwo) noble metals on a solid support comprising cerium oxide. It ispossible that CO₂ alone can serve as the oxidant for the methane and/orother hydrocarbon(s) to CO and H₂ according to the dry reforming of suchhydrocarbons, which in the case of alkanes, for example, can begeneralized as:

C_(n)H_(2n+2)nCO₁→2nCO+(n+1)H₂.

In preferred embodiments a combination of CO₂ and H₂O can serve as theoxidant, that is, in embodiments in which the gaseous mixture furthercomprises H₂O. The reaction in this case is a “CO₂-steam reformingreaction,” which also includes steam reforming as a route for producingsyngas from methane and/or other hydrocarbons, which in the case ofalkanes, for example, can be generalized as:

C_(n)H_(2n+n)+NH₂O→nCO+(2n+1)H₂.

Whereas the theoretical molar H₂:CO ratio of a synthesis gas productformed from the dry reforming of methane is 1, the addition of steamreforming, in the CO₂-steam reforming of methane, advantageouslyprovides the potential to increase this molar ratio to values morefavorable for downstream Fischer-Tropsch synthesis to produce liquidhydrocarbons, according to:

(2n+1) H₂+nCO→C_(n)H_(2n−2)nH₂O.

From this, it can be observed that C₄ ⁺ hydrocarbons, such as C₄-C₁₂hydrocarbons, which are desirable as liquid fuels or components ofliquid fuels, are formed ideally at molar H₂:CO ratios approaching 2.Importantly, the use of steam (H₂O as an oxidant in combination with CO₂provides an advantageous “handle” or control parameter for adjusting themolar H₂:CO ratio of the synthesis gas product over a wide range ofCO₂-steam reforming conditions. In fact, for any given set of suchconditions (e.g., conditions within the reactor such as temperature,pressure, weight hourly space velocity, and catalyst formulation) underwhich the combined CO₂ and steam reforming reactions are carried out, arelationship can be established between the molar H₂O:CO₂ ratio of thegaseous mixture (e.g., combined reactor feed) and the molar H₂:CO ratioof the synthesis gas product (e.g., reactor effluent). Whereas the dryreforming and steam reforming of hydrocarbons other than methane produceH₂ and CO at other molar ratios, directionally the same shifts oradjustments in product yields may be achieved by varying the relativeamounts of the oxidants H₂O and CO₂ in the gaseous mixture that issubjected to CO₂-steam reforming. Accordingly, embodiments of theinvention are directed to a CO₂-steam reforming process comprisingdetermining a molar H₂:CO ratio of the synthesis gas product and, basedon the molar H₂:CO ratio, adjusting a molar H₂O:CO₂ ratio of the gaseousmixture toward a target molar H₂:CO ratio of the synthesis gas product,for example a target molar H₂:CO ratio of 2:1, or otherwise a targetmolar H₂:CO ratio range generally from about 1.5:1 to about 2.5:1,typically from about 1.5:1 to about 2.3:1, and often from about 1.8:1 toabout 2.2:1.

More specifically, the molar H₂O:CO₂ ratio of the gaseous mixture may beincreased to increase, toward the target molar H₂:CO ratio, an observedmolar H₂:CO ratio of the synthesis gas product that is below the target.Conversely, the molar H₂O:CO₂ ratio of the gaseous mixture may bedecreased to decrease, toward the target molar H₂:CO ratio, an observedmolar H₂:CO ratio of the synthesis gas product that is above the target.Any such adjustments to the molar H₂O:CO₂ ratio of the gaseous mixturemay be performed, for example, by adjusting the flow rate(s) of one ormore components of the gaseous mixture (e.g., combined feed), such asone or more of a methane-containing feedstock (or hydrocarbon-containingfeedstock generally), a CO₂-containing oxidant, and an H₂O-containingoxidant, relative to the flow rate(s) of one or more other of suchcomponents. According to a specific example, the molar H₂O:CO₂ ratio ofthe combined feed to the reactor may be increased or decreased, byincreasing or decreasing, respectively, the flow rate of steam (as theH₂O-containing oxidant), thereby resulting in a respective increase ordecrease in the molar H₂O:CO₂ ratio of the gaseous mixture.

In addition to providing the ability to control the molar H₂:CO ratio ofthe synthesis gas product over a favorable range of values, the use ofsteam (H₂O) as an oxidant in combination with CO₂ furthermoresurprisingly reduces the rate of carbon (coke) formation compared topure dry reforming, thereby extending the life of catalysts as describedherein. Accordingly, further embodiments of the invention are directedto a CO₂-steam reforming process in which the rate of carbon formation(e.g., using suitable ratios or concentrations/partial pressures of CO₂and H₂O oxidants, in combination with a catalyst as described herein) isless than the rate of carbon formation of a baseline process (i.e.,baseline dry reforming process), in which all parameters are maintainedthe same, except for the replacement of H₂O in the gaseous mixture(e.g., combined reactor feed) with an equimolar amount of oxygen as CO₂(i.e., replacement of the moles of H₂O with ½ the moles of CO₂). Coupledwith this comparatively lower carbon formation relative to the baselineprocess, the synthesis gas product may have a molar H₂/CO ratio asdescribed herein (e.g., from about 1.5:1 to about 2.3:1).

Catalysts as described herein furthermore exhibit a surprising degree ofsulfur tolerance, which is particularly advantageous, for example, inthe case of methane-containing feedstocks comprising or derived fromnatural gas that, depending on its source, may contain a significantconcentration (e.g., several weight percent by volume or more) of H₂S.In this regard, conventional steam methane reforming (SMR) processesrequire pretreatment to reduce the feed total sulfur content totypically less than 1 mol-ppm to protect the catalyst from sulfurpoisoning. In contrast, according to representative embodiments of thepresent invention, the gaseous mixture or any of its components,particularly the hydrocarbon-containing feedstock, is not subjected to,or otherwise has not undergone, a sulfur removal pretreatment step. Suchembodiments provide substantial economic benefits over known processeswith stringent desulfurization requirements and associated expenses, asnecessary to achieve favorable catalyst life. In contrast to such knownprocesses, a gaseous mixture in a dry reforming or CO₂-steam reformingprocess as described herein may comprise sulfur generally at anyconcentration representative of the source of the hydrocarbon feedstock,such as natural gas, not having undergone pretreatment for sulfurremoval, but also accounting for the potential dilution of the sulfurwhen combined with other components of the gaseous mixture (e.g., CO₂)having a lower sulfur concentration. For example, the gaseous mixturemay comprise generally at least about 1 mole-ppm (e.g., from about 1mol-ppm to about 10 mol-%) total sulfur (e.g., as H₂S and/or othersulfur-bearing contaminants). The gaseous mixture may comprise typicallyat least about 10 mol-ppm (e.g., from about 10 mol-ppm to about 1 mol-%)and often at least about 100 mol-ppm (e.g., from about 100 mol-ppm toabout 1000 mol-ppm) of total sulfur. For example, a range from about 500mol-ppm to about 1000 mol-ppm of total sulfur, according to particularembodiments, generally poses no, or at least a negligible, adverseeffect on the stability of reforming catalysts as described herein.

With respect to sulfur tolerance of catalysts described herein, furtheraspects of the invention are associated with the discovery that higherlevels (concentrations) of sulfur in the gaseous mixture may becompensated for by increasing the reaction temperature, i.e.,temperature of the bed of catalyst as described herein, contained in areactor. That is, increased sulfur concentrations have been found toimpact catalyst activity, as measured by decreased conversion of methaneand/or or other hydrocarbon(s) in the gaseous mixture, if all otheroperating parameters remain unchanged. However, the desired conversionlevel can be restored by increasing the reaction temperature. Forexample, under certain operating conditions, a 28° C. (50° F.) increasecan be sufficient to restore a loss in catalyst activity thataccompanies a concentration of 800 mol-ppm H₂S in the gaseous mixture,relative to the activity without any sulfur in the gaseous mixture.Accordingly, embodiments of the invention are directed to a dryreforming process or a CO₂-steam reforming process as described hereincomprising determining a conversion of methane and/or otherhydrocarbon(s) (e.g., a conversion of combined C₁-C₄ hydrocarbons orcombined C₁-C₃ hydrocarbons), or otherwise determining a sulfur level(such as an H₂S level) in the gaseous mixture or synthesis gas productand, based on the conversion or sulfur level, adjusting the reactiontemperature toward a target conversion of methane and/or otherhydrocarbon(s), for example a target conversion of at least about 75%(e.g., any specific conversion value in the range from about 75% toabout 100%), such as a target conversion of at least about 85% (e.g.,any specific conversion value in the range from about 85% to about 99%).

Importantly, however, such decreases in the activity of catalystsdescribed herein, accompanying increases in the concentration of sulfurin the gaseous mixture, are not further accompanied by any appreciableloss in catalyst stability. That is, the compensating reactortemperature increases, as described herein to offset higher sulfurlevels, do not significantly impact the ability of the catalyst toachieve stable operating performance over an extended period. Thisfinding is contrary to expectations based on conventional reformingtechnologies, in which the presence of even small quantities (e.g.,mol-ppm levels) of sulfur in feeds must be prevented to avoiddeactivation and costly premature replacement of the catalyst. Acharacteristic sulfur tolerance, or activity stability in the presenceof sulfur-bearing contaminants, of catalysts as described herein can bedetermined according to a standard test in which a small, 5-100 gramcatalyst sample is loaded into a fixed-bed reactor and contacted with afeed blend of 30 mol-% methane, 30 mol-% CO₂, and 30 mol-% H₂O that isspiked with 800 mol-ppm of H₂S. In this standard test, with flowingconditions of 0.7 hr⁻¹ WHSV, a catalyst bed temperature of 788° C.(1450° F.), and a reactor pressure of 138 kPa (20 psig), a conversion ofthe methane of at least 85%, and preferably at least 95%, is maintained,at constant catalyst bed temperature, for at least 50 hours ofoperation, and more typically for at least 100 hours of operation, oreven for at least 400 hours of operation.

The tolerance, or “robustness” of catalysts described herein is furthermanifested in a high stability against deactivation in the presence ofother compounds in the gaseous mixture, including higher molecularweight hydrocarbons such as reactive aromatic hydrocarbons and/orolefinic hydrocarbons that are normally considered prone to causingcatalyst deactivation through coking. For example, the gaseous mixturemay comprise aromatic and olefinic hydrocarbons in a combined amount ofgenerally at least about 1 mole-% (e.g., from about 1 mol-% to about 25mol-%), such as at least about 3 mol-% (e.g., from about 3 mol-% toabout 20 mol-%) or more particularly at least about 5 mol-% (e.g., fromabout 5 mol-% to about 15 mol-%). At such levels of aromatic and/orolefinic hydrocarbons, catalyst stability may be exhibited according tothe same activity stability test as defined above with respect to sulfurtolerance, with the exception of the feed blend containing theseconcentrations of aromatic and/or olefinic hydrocarbons as opposed toH₂S. This tolerance of catalysts as described herein with respect toboth sulfur and reactive hydrocarbons allows for the reforming ofwide-ranging hydrocarbon-containing feedstocks, including variousfractions (e.g., naphtha and jet fuel) obtained from crude oil refiningas described in greater detail below.

More generally, the gaseous mixture, and particularly thehydrocarbon-containing feedstock component of this mixture, maycomprise, in addition to methane, other hydrocarbons such as C₂, C₃,and/or C₄ hydrocarbons (e.g., ethane, propane, propylene, butane, and/orbutenes) that may be present in natural gas and/or other sources ofmethane). Alternatively, catalysts as described herein may be used fordry reforming or CO₂-steam reforming of predominantly, or only, highermolecular weight hydrocarbons, such as in the case of the hydrocarbonsin gaseous mixture comprising, or optionally consisting of, any one ormore compounds selected from the group consisting of a C₄ hydrocarbon, aC₅ hydrocarbon, a C₆ hydrocarbon, a C₇ hydrocarbon, a C₈ hydrocarbon, aC₉ hydrocarbon, a C₁₀ hydrocarbon, a C₁₁ hydrocarbon, a C₁₂ hydrocarbon,a C₁₃ hydrocarbon, a C₁₄ hydrocarbon, a C₁₅ hydrocarbon, a C₁₆hydrocarbon, a C₁₇ hydrocarbon, a C₁₈ hydrocarbon, and combinationsthereof. For example, the hydrocarbons in the gaseous mixture maycomprise, or consist of, C₄-C₈ or C₄-C₆ hydrocarbons, in the case of dryreforming or CO₂-steam reforming of naphtha boiling-range hydrocarbons(naphtha reforming). As another example, the hydrocarbons in the gaseousmixture may comprise, or consist of, C₈-C₁₈ or C₈-C₁₄ hydrocarbons, inthe case of dry reforming or CO₂-steam reforming of jet fuelboiling-range hydrocarbons (jet fuel reforming). Such naphthaboiling-range hydrocarbons and jet fuel boiling-range fractions arenormally obtained as products from crude oil refining and, as such, canbe a source of sulfur-bearing contaminants in the gaseous mixture. Inrepresentative embodiments, the gaseous mixture may comprise methaneand/or any of the hydrocarbons described herein in a combined amountgenerally from about 5 mol-% to about 85 mol-%, typically from about 10mol-% to about 65 mol-%, and often from about 20 mol-% to about 45mol-%. The gaseous mixture may further comprise CO₂ in an amountgenerally from about 8 mol-% to about 90 mol-%, typically from about 15mol-% to about 75 mol-%, and often from about 20 mol-% to about 50mol-%. In the case of CO₂-steam reforming, the gaseous mixture maycomprise H₂O in an amount generally from about 15 mol-% to about 70mol-%, typically from about 20 mol-% to about 60 mol-%, and often fromabout 25 mol-% to about 55 mol-%. The balance of the gaseous mixture mayinclude contaminants such as H₂Sand/or other sulfur-bearing contaminantsas described above.

In the case of gaseous mixtures comprising methane and/or lighthydrocarbons (e.g., C₂-C₃ or C₂-C₄ hydrocarbons), the synthesis gasproduct of dry reforming or CO₂-steam reforming may advantageously beused with a favorable molar H₂:CO ratio in the downstream production ofliquid hydrocarbon fuels through Fischer-Tropsch synthesis, as describedabove. The synthesis gas may alternatively be used for other downstreamapplications associated with conventional steam methane reforming (SMR).For example, Tarun (INTERNATIONAL JOURNAL OF GREENHOUSE GAS CONTROL I(2007): 55-61) describes a conventional hydrogen production processinvolving SMR. If dry reforming or CO₂-steam reforming, as describedherein, is applied in hydrogen production, according to embodiments ofthe invention, representative processes may further comprise steps of(i) subjecting the synthesis gas product to one or more water-gas shift(WGS) reaction stages to increase its hydrogen content and/or (ii)separating the effluent of the WGS stage(s), or otherwise separating thesynthesis gas product without intervening WGS stage(s), as the case maybe (e.g., by pressure-swing adsorption (PSA) or membrane separation), toprovide a hydrogen-enriched product stream and a hydrogen-depleted PSAtail gas stream. The hydrogen-enriched product stream may then be usedin a conventional refinery process such as a hydrotreating process(e.g., hydrodesulfurization, hydrocracking, hydroisomerization, etc.).The hydrogen-depleted PSA tail gas stream may then be separated torecover hydrogen and/or used as combustion fuel to satisfy at least someof the heating requirements of the dry reforming or CO₂-steam reforming.In yet further embodiments, the CO- and H₂-containing PSA tail gas maybe passed to a biological fermentation stage for the production offermentation products such as alcohols (e.g., ethanol). The gaseouseffluent from the fermentation stage may then be separated to recoverhydrogen and/or used as combustion fuel as described above. With respectto conventional hydrogen production, the further integration of abiological fermentation stage is described, for example, in U.S. Pat.Nos. 9,605,286; 9,145,300; US 2013/0210096; and US 2014/0028598. As analternative to integration in a hydrogen production process, dryreforming or CO₂-steam reforming as described herein may be used toprovide a synthesis gas product that is used directly in the downstreamproduction of fermentation products using suitable carboxydotrophicbacteria (e.g., of the species Clostridium autoethanogenum orClostridium ljungdahlii). In either case, i.e., with or without suchintegration, the microorganisms used for the fermentation may be sulfurtolerant or even require sulfur in the cell culture medium, such thatthe sulfur tolerance of catalysts as described herein can beparticularly advantageous over conventional reforming catalysts, interms of compatibility and cost savings associated with the eliminationof, or at the least reduced requirements for, upstream sulfur removal.

Aspects of the invention therefore relate to dry reforming processes andCO₂-steam reforming processes for producing a synthesis gas product(i.e., comprising both H₂ and CO, and optionally other gases such asunconverted CO₂, H₂O, and/or hydrocarbons). In representativeembodiments, a gaseous mixture comprising methane and/or otherhydrocarbon(s) may be provided batchwise, but preferably as a continuousflow, to a reactor of a dry reforming process (in the case of the feedor gaseous mixture further comprising CO₂ but no water) or a CO₂-steamreforming process (in the case of the feed or gaseous mixture furthercomprising both CO₂ and water). A synthesis gas product, in turn, may bewithdrawn batchwise (if the gaseous mixture is provided batchwise), butpreferably as a continuous flow (if the gaseous mixture is provided as acontinuous flow), from the reactor.

In addition to H₂, CO, and optionally other gases, water (H₂O) may alsobe present in the synthesis gas product, although at least a portion ofthe water that is present in vapor form may be readily separated bycooling/condensation, for example upstream of a Fischer-Tropschsynthesis reactor (FT reactor) used to convert the synthesis gas productto liquid hydrocarbons. Neither water nor CO₂ in the synthesis gasproduct has an effect on its molar H₁CO ratio which, as described above,is an important parameter in determining the suitability of thesynthesis gas product as a direct feed stream to the FT reactor.

In representative processes, a gaseous mixture comprising methane and/orother light hydrocarbon(s) (e.g., ethane, ethylene, propane, and/orpropylene) and CO₂, as well as optionally H₂O, is contacted with acatalyst having activity for carrying out the reforming of suchhydrocarbon(s). In particular, such hydrocarbon(s), for example themajority of such hydrocarbons, may be reformed (i) through theiroxidation with some or all of the CO₂ only, according to a dry reformingprocess, or (ii) through their oxidation with both some or all of theCO₂ and some of all of the H₂O (if present), according to a CO₂-steamreforming process.

As described above, aspects of the invention are associated with thediscovery of reforming catalysts for such dry reforming and CO₂-steamreforming processes, exhibiting important advantages, particularly interms of sulfur tolerance and/or a reduced rate of carbon formation(coking), compared to conventional reforming catalysts. Thesecharacteristics, in turn, reduce the rate of catalyst deactivationthrough poisoning and/or coking mechanisms that chemically and/orphysically block active catalyst sites. Further improvements in catalyststability result at least in part from the high activity of catalystsdescribed herein, as necessary to lower the substantial activationenergy barrier associated with the use of CO₂ as an oxidant for methaneand/or other hydrocarbon(s), as described above. This high activitymanifests in lower operating (reactor or catalyst bed) temperatures,which further contribute to the reduced rate of carbon deposition (cokeformation) on the catalyst surface and extended, stable operation.According to particular embodiments, processes utilizing catalystsdescribed herein can maintain stable operating parameters as describedherein, for example in terms of hydrocarbon conversion (e.g., at leastabout 85% conversion of methane and/or other hydrocarbon(s)) and/ormolar H₂/CO ratio (e.g., from about 1.5:1 to about 2.3:1) of thesynthesis gas product, for at least about 100, at least about 300, oreven at least about 500, hours of continuous or possibly discontinuousoperation. This may be an operating period over which (i) the catalystdoes not undergo regeneration, for example according to a reformingprocess utilizing the catalyst as a fixed bed within the reactor and/or(ii) the temperature of the reactor or catalyst bed is not raised beyonda threshold temperature difference from the start of the time period tothe end of the time period, with this threshold temperature differencebeing, for example, 100° C. (180° F.), 50° C. (90° F.), 25° C. (45° F.),10° C. (18° F.), or even 5° C. (9° F.).

Representative reforming catalysts suitable for catalyzing the reactionof methane and/or other hydrocarbon(s) with CO₂ and optionally also withH₂O comprise a noble metal, and possibly two or more noble metals, on asolid support. The phrase “on a solid support” is intended to encompasscatalysts in which the active metal(s) is/are on the support surfaceand/or within a porous internal structure of the support. The solidsupport preferably comprises a metal oxide, with cerium oxide being ofparticular interest. Cerium oxide may be present in an amount of atleast about 80 wt-% and preferably at least about 90 wt-%, based on theweight of the solid support (e.g., relative to the total amount(s) ofmetal oxide(s) in the solid support). The solid support may comprise allor substantially all (e.g., greater than about 95 wt-%) cerium oxide.Other metal oxides, such as aluminum oxide, silicon oxide, titaniumoxide, zirconium oxide, magnesium oxide, strontium oxide, etc., may alsobe present in the solid support, in combined amounts representing aminor portion, such as less than about 50 wt-%, less than about 30 wt-%,or less than about 10 wt-%, of the solid support. In other embodiments,the solid support may comprise such other metal oxides alone or incombination, with a minor portion (e.g., less than about 50 wt-% or lessthan about 30 wt-%) of cerium oxide.

Noble metals are understood as referring to a class of metallic elementsthat are resistant to oxidation. In representative embodiments, thenoble metal, for example at least two noble metals, of the catalyst maybe selected from the group consisting of platinum (Pt), rhodium (Rh),ruthenium (Ru), palladium (Pd), silver (Ag), osmium (Os), iridium (Ir),and gold (Au), with the term “consisting of” being used merely to denotegroup members, according to a specific embodiment, from which the noblemetal(s) are selected, but not to preclude the addition of other noblemetals and/or other metals generally. Accordingly, a catalyst comprisinga noble metal embraces a catalyst comprising at least two noble metals,as well as a catalyst comprising at least three noble metals, andlikewise a catalyst comprising two noble metals and a third, non-noblemetal such as a promoter metal (e.g., a transition metal). According topreferred embodiments, the noble metal is present in an amount, oralternatively the at least two noble metals are each independentlypresent in amounts, from about 0.05 wt-% to about 5 wt-%, from about 0.3wt-% to about 3 wt-%, or from about 0.5 wt-% to about 2 wt-%, based onthe weight of the catalyst. For example, a representative catalyst maycomprise the two noble metals Pt and Rh, and the Pt and Rh mayindependently be present in an amount within any of these ranges (e.g.,from about 0.05 wt-% to about 5 wt-%). That is, either the Pt may bepresent in such an amount, the Rh may be present in such an amount, orboth Pt and Rh may be present in such amounts.

In representative embodiments, the at least two noble metals (e.g., Ptand Rh) may be substantially the only noble metals present in thecatalyst, such that, for example, any other noble metal(s) is/arepresent in an amount or a combined amount of less than about 0.1 wt-%,or less than about 0.05 wt-%, based on the weight of the catalyst. Infurther representative embodiments, that at least two noble metals(e.g., Pt and Rh) are substantially the only metals present in thecatalyst, with the exception of metals present in the solid support(e.g., such as cerium being present in the solid support as ceriumoxide). For example, any other metal(s), besides at least two noblemetals and metals of the solid support, may be present in an amount or acombined amount of less than about 0.1 wt-%, or less than about 0.05wt-%, based on the weight of the catalyst. Any metals present in thecatalyst, including noble metal(s), may have a metal particle size inthe range generally from about 0.3 nanometers (nm) to about 20 nm,typically from about 0.5 nm to about 10 nm, and often from about 1 nm toabout 5 nm.

The noble metal(s) may be incorporated in the solid support according toknown techniques for catalyst preparation, including sublimation,impregnation, or dry mixing. In the case of impregnation, which is apreferred technique, an impregnation solution of a soluble compound ofone or more of the noble metals in a polar (aqueous) or non-polar (e.g.,organic) solvent may be contacted with the solid support, preferablyunder an inert atmosphere. For example, this contacting may be carriedout, preferably with stirring, in a surrounding atmosphere of nitrogen,argon, and/or helium, or otherwise in a non-inert atmosphere, such asair. The solvent may then be evaporated from the solid support, forexample using heating, flowing gas, and/or vacuum conditions, leavingthe dried, noble metal-impregnated support. The noble metal(s) may beimpregnated in the solid support, such as in the case of two noblemetals being impregnated simultaneously with both being dissolved in thesame impregnation solution, or otherwise being impregnated separatelyusing different impregnation solutions and contacting steps. In anyevent, the noble metal-impregnated support may be subjected to furtherpreparation steps, such as washing with the solvent to remove excessnoble metal(s) and impurities, further drying, calcination, etc. toprovide the catalyst.

The solid support itself may be prepared according to known methods,such as extrusion to form cylindrical particles (extrudates) or oildropping or spray drying to form spherical particles. Regardless of thespecific shape of the solid support and resulting catalyst particles,the amounts of noble metal(s) being present in the catalyst, asdescribed above, refer to the weight of such noble metal(s), on average,in a given catalyst particle (e.g., of any shape such as cylindrical orspherical), independent of the particular distribution of the noblemetals within the particle. In this regard, it can be appreciated thatdifferent preparation methods can provide different distributions, suchas deposition of the noble metal(s) primarily on or near the surface ofthe solid support or uniform distribution of the noble metal(s)throughout the solid support. In general, weight percentages describedherein, being based on the weight of the solid support or otherwisebased on the weight of catalyst, can refer to weight percentages in asingle catalyst particle but more typically refer to average weightpercentages over a large number of catalyst particles, such as thenumber in a reactor that form a catalyst bed as used in processesdescribed herein.

Simplified illustrations of dry reforming processes and optionallyCO₂-steam reforming processes 10 are depicted in FIGS. 1A and 1B. Ineither of these embodiments, gaseous mixture 4 comprising one or morehydrocarbons (e.g., methane) and CO₂, may reside within reactor 5 in theform of a vessel that is used to contain a bed of catalyst 6, asdescribed above, under reforming conditions at which gaseous mixture 4and catalyst 6 are contacted. According to the embodiment illustrated inFIG. 1A, gaseous mixture 4 may be provided within reactor 5 fromhydrocarbon-containing feedstock 1 alone. For example, a representativehydrocarbon-containing feedstock is a methane-containing feedstock thatis obtained from biomass gasification or pyrolysis, includinghydrogasification or hydropyrolysis, and may further comprise CO₂ andH₂O. Such a hydrocarbon-containing feedstock may thereby itself providegaseous mixture 4 for a CO₂-steam reforming process, in which both CO₂and H₂O react as oxidants of methane. In other embodiments, gaseousmixture 4 may be obtained from combining hydrocarbon-containingfeedstock 1 with optional CO₂-containing oxidant 2, if, for example,hydrocarbon-containing feedstock 1 contains little CO₂ such as in thecase of liquid hydrocarbons including naphtha boiling-range hydrocarbonsand/or jet fuel boiling-range hydrocarbons, or otherwise in the case ofsome types of natural gas.

As another option, H₂O-containing oxidant 3 (e.g., as steam) may also becombined to form gaseous mixture 4, comprising methane and both CO₂ andH₂O oxidants for a CO₂-steam reforming processes. Again, however, H₂Omay also be present in sufficient quantity in hydrocarbon-containingfeedstock 1 and/or CO₂-containing oxidant 2, such that separateH₂O-containing oxidant 3 may not be necessary. As shown by dashed,double-headed arrows between hydrocarbon-containing feedstock 1,CO₂-containing oxidant 2, and H₂O-containing oxidant 3, it is clear thatany of these may be combined prior to (e.g., upstream of) reactor 5.According to a specific embodiment, FIG. 1B illustrateshydrocarbon-containing feedstock 1 being combined with optionalCO₂-containing oxidant 2 and optional H₂O-containing oxidant 3 toprovide gaseous mixture 4 both prior to (e.g., upstream of) reactor 5,as well as within this reactor.

As described above, in embodiments in which gaseous mixture 4 comprisesone or more hydrocarbons such as methane and CO₂, but not H₂O, theprocess may be considered a “dry reforming” process, whereas inembodiments in which gaseous mixture 4 comprises hydrocarbon(s) and CO₂,and further comprises H₂O acting, in combination with the CO₂, asoxidants of the hydrocarbon(s) (e.g., such that at least respectiveoxidant portions of the CO₂ and H₂O oxidize respective reactant portionsof the hydrocarbon(s)), the process may be considered a “CO₂-steamreforming process.” Catalysts as described herein provide advantageousresults in both dry reforming and CO₂-steam reforming, in terms of bothactivity and stability, as described above. Under reforming conditionsprovided in reactor 5, gaseous mixture 4 is converted to synthesis gasproduct 7, which may, relative to gaseous mixture 4, be enriched in(i.e., have a higher concentration of) hydrogen and CO, and/or bedepleted in (i.e., have a lower concentration of) CO₂, H₂O, methane,and/or other hydrocarbon(s) initially present in gaseous mixture 4.

An important methane-containing feedstock is natural gas, andparticularly stranded natural gas, which, using known processes, is noteasily converted to a synthesis gas product in an economical manner.Natural gas comprising a relatively high concentration of CO₂, forexample at least about 10 mol-% or even at least about 25 mol-%,represents an attractive methane-containing feedstock, since processesas described herein do not require the removal of CO₂ (e.g., byscrubbing with an amine solution), in contrast to conventional steamreforming, and in fact utilize CO₂ as a reactant. Othermethane-containing feedstocks may comprise methane obtained from coal orbiomass (e.g., lignocellulose or char) gasification, from a biomassdigester, or as an effluent from a renewable hydrocarbon fuel (biofuel)production process (e.g., a pyrolysis process, such as a hydropyrolysisprocesses, or a fatty acid/triglyceride hydroconversion processes).Further methane-containing feedstocks may comprise methane obtained froma well head or an effluent of an industrial process including apetroleum refining process (as a refinery off gas), an electric powerproduction process, a steel manufacturing process or a non-ferrousmanufacturing process, a chemical (e.g., methanol) production process,or a coke manufacturing process. Generally, any process gas known tocontain a hydrocarbon (e.g., a C₁-C₃ hydrocarbon) and CO₂ may provideall or a portion of the gaseous mixture as described herein, or at leastall or a portion of the methane-containing feedstock as a component ofthis mixture. If the methane-containing feedstock comprises methaneobtained from a renewable resource (e.g., biomass), for example methanefrom a process stream obtained by hydropyrolysis as described in U.S.Pat. No. 8,915,981 assigned to Gas Technology Institute, then processesdescribed herein may be used to produce renewable synthesis gas products(i.e., comprising renewable CO) that, in turn, can be further processedto provide renewable hydrocarbon-containing fuels, fuel blendingcomponents, and/or chemicals. Accordingly, the methane-containingfeedstock may therefore comprise methane from a non-renewable source(e.g., natural gas) and/or methane from a renewable source (e.g.,biomass), with the latter source imparting an overall reduction in thecarbon footprint associated with the synthesis gas product anddownstream products. As further described herein, natural gas and/orother methane-containing feedstocks may be, but need not be, pretreatedto remove H₂S and other sulfur-bearing contaminants, prior to dryreforming or CO₂-steam reforming.

In representative embodiments, gaseous mixture 4 comprising ahydrocarbon and CO₂ may be contacted with catalyst 6 in a batchwise ordiscontinuous operation, but preferably the dry reforming or CO₂-steamreforming process is performed continuously with flowing streams of thegaseous mixture 4 or components thereof (e.g., hydrocarbon-containingfeedstock 1, CO₂-containing oxidant 2, and/or H₂O-containing oxidant 3as described herein), to improve process efficiency. For example,contacting may be performed by continuously flowing the gaseous mixture4 (e.g., as a combined reactor feed stream of any of these components incombination) through the reactor 5 and catalyst 6 under reformingconditions (e.g., conditions within a reactor vessel and within a bed ofthe catalyst that is contained in the vessel) that include a suitableflow rate. In particular embodiments, the reforming conditions mayinclude a weight hourly space velocity (WHSV) generally from about 0.05hr⁻¹ to about 10 hr⁻¹, typically from about 0.1 hr⁻¹ to about 4.0 hr⁻¹,and often from about 0.3 hr⁻¹ to about 2.5 hr⁻¹. As is understood in theart, the WHSV is the weight flow of the gaseous mixture divided by theweight of the catalyst in the reactor and represents the equivalentcatalyst bed weights of the feed stream processed every hour. The WHSVis related to the inverse of the reactor residence time. The catalyst 6may be contained within reactor 5 in the form of a fixed bed, but othercatalyst systems are also possible, such as moving bed and fluidized bedsystems that may be beneficial in processes using continuous catalystregeneration.

Other reforming conditions, which are useful for either dry reforming orCO₂-steam reforming, include a temperature generally from about 649° C.(1200° F.) to about 816° C. (1500° F.). Processes described herein, byvirtue of the high activity of the catalyst in terms of reducing theactivation energy barrier required for the use of CO₂ as an oxidant, caneffectively oxidize methane and/or other hydrocarbons at significantlylower temperatures, compared to a representative conventionaltemperature of 816° C. (1500° F.) that is used for dry reforming orsteam reforming. For example, in representative embodiments, thereforming conditions can include a temperature in a range from about677° C. (1250° F.) to about 788° C. (1450° F.), or from about 704° C.(1300° F.) to about 760° C. (1400° F.). As described above, the presenceof H₂S and/or other sulfur-bearing contaminants in significant amounts(e.g., 100-1000 mol-ppm) may warrant increased temperatures, for examplein a range from about 732° C. (1350° F.) to about 843° C. (1550° F.), orfrom about 760° C. (1400° F.) to about 816° C. (1500° F.), to maintaindesired conversion levels (e.g., greater than about 85%). Yet otherreforming conditions can include an above-ambient pressure, i.e., apressure above a gauge pressure of 0 kPa (0 psig), corresponding to anabsolute pressure of 101 kPa (14.7 psia). Because the reformingreactions make a greater number of moles of product versus moles ofreactant, equilibrium is favored at relatively low pressures. Therefore,reforming conditions can include a gauge pressure generally from about 0kPa (0 psig) to about 517 kPa (75 psig), typically from about 0 kPa (0psig) to about 345 kPa (50 psig), and often from about 103 kPa (15 psig)to about 207 kPa (30 psig).

Advantageously, within any of the above temperature ranges, the highactivity of the catalyst can achieve a conversion of methane and/orother hydrocarbon(s) (e.g., a conversion of methane, a conversion ofcombined C₁-C₃ hydrocarbons, a conversion of combined C₁-C₄hydrocarbons, a conversion of naphtha boiling-range hydrocarbons, aconversion of jet fuel boiling-range hydrocarbons, etc.) of at leastabout 80% (e.g., from about 80% to about 99%), at least about 85% (e.g.,from about 85% to about 97%), or at least about 90% (e.g., from about90% to about 99%), for example by adjusting the particular reactor orcatalyst bed temperature and/or other reforming conditions (e.g., WHSVand/or pressure) as would be appreciated by those having skill in theart, with knowledge gained from the present disclosure. Advantageously,catalysts as described herein are sufficiently active to achieve asignificant hydrocarbon (e.g., methane) conversion, such as at leastabout 85%, in a stable manner at a temperature of at most about 732° C.(1350° F.), or even at most about 704° C. (1300° F.). With respect tothe oxidant reactants, a representative conversion of CO₂ is at leastabout 50% (e.g., from about 50% to about 75%), and a representativeconversion of H₂O is at least about 70% (e.g., from about 70% to about90%), at the conversion levels described herein with respect tohydrocarbon(s). As is understood in the art, conversion of anyparticular compound (e.g., methane) or combination of compounds (e.g.,C₁-C₄ hydrocarbons or C₁-C₃ hydrocarbons) can be calculated on the basisof:

100*(X_(feed)−X_(prod))/X_(feed),

wherein X_(feed) is the total amount (e.g., total weight or total moles)of the compound(s) X in the gaseous mixture (e.g., combined reactorfeed) provided to a reactor and X_(prod) is the total amount of thecompound(s) X in the synthesis gas product removed from the reactor. Inthe case of continuous processes, these total amounts may be moreconveniently expressed in terms of flow rates, or total amounts per unittime (e.g., total weight/hr or total moles/hr). Other performancecriteria that can be achieved using catalysts and reforming conditionsas described herein include a high hydrogen yield, or portion of thetotal hydrogen in the methane and/or other hydrogen-containing compounds(e.g., total hydrogen in the hydrocarbons such as C₂-C₄ hydrocarbons orC₂-C₃ hydrocarbons), in the gaseous mixture provided to the reactor,which is converted to H₂ in the synthesis gas product removed from thereactor. In representative embodiments, the hydrogen yield is at leastabout 70% (e.g., from about 70% to about 85%). As described above withrespect to conversion, amounts provided to and removed from the reactormay be expressed in terms of flow rates.

As described above, further advantages associated with reformingprocesses, and particularly CO₂-steam reforming processes, as describedherein, include favorable molar H₂/CO ratios, as well as the ability toadjust these ratios, in the synthesis gas product. This has especiallyimportant implications for downstream processing via Fischer-Tropsch forthe production of liquid hydrocarbons. The exact composition of thesynthesis gas product depends on the composition of the feed (e.g.,combined reactor feed) or gaseous mixture, the catalyst, and thereforming conditions.

In representative embodiments, the synthesis gas product, particularlyin the case of a CO₂-steam reforming process, advantageously has a molarH₂:CO ratio that is near 2:1, for example generally in a range fromabout 1.5:1 to about 2.3:1, and typically from about 1.8:1 to about2.2:1. The combined concentration of H₂, and CO in this product isgenerally at least about 35 mol-% (or vol-%) (e.g., from about 35 mol-%to about 85 mol-%), typically at least about 50 mol-% (e.g., from about50 mol-% to about 80 mol-%), and often at least about 60 mol-% (e.g.,from about 60 mol-% to about 75 mol-%). As described above, the balanceof the synthesis gas product may be substantially or all CO₂ and water,depending on the particular dry reforming or CO₂-steam reformingprocess, including the conditions of such process (e.g., conditionswithin the reactor such as temperature, pressure, weight hourly spacevelocity, and catalyst formulation) and the feed or gaseous mixturebeing reacted. In representative embodiments, CO₂ is present in thesynthesis gas product in a concentration of generally less than about 45mol-% (e.g., from about 5 mol-% to about 45 mol-%) and typically lessthan about 35 mol-% (e.g., from about 10 mol-% to about 35 mol-%). Watermay be present in a concentration of generally less than about 20 mol-%(e.g., from about 1 mol-% to about 25 mol-%) and typically less thanabout 15 mol-% (e.g., from about 5 mol-% to about 15 mol-%). Minoramounts of unconverted hydrocarbons may also be present in the synthesisgas product. For example, a combined amount of C₁-C₄ hydrocarbons (e.g.,a combined amount of methane, ethane, propane, and butane), which maypossibly include only C₁-C₃ hydrocarbons, may be present in aconcentration of less than about 5 mol-% and typically less than about 2mol-%.

The following examples are set forth as representative of the presentinvention. These examples are not to be construed as limiting the scopeof the invention as other equivalent embodiments will be apparent inview of the present disclosure and appended claims.

EXAMPLE 1

Pilot plant scale experiments were performed in which gaseous mixtureswere fed continuously to a reactor containing catalyst particles havinga composition of 1 wt-% Pt and 1 wt-% Rh on a cerium oxide support. Theperformance of the system for CO₂-steam reforming was tested atconditions of 0.7 hr⁻¹ WHSV, 760° C. (1400° F.), and a gauge pressureranging from 124 kPa (18 psig) to 172 kPa (25 psig). Two types ofgaseous mixtures tested were (1) a composition containing methane,ethane, propane, and CO₂, in addition to H₂O, and simulating thatobtained from the combined hydropyrolysis and hydroconversion of biomass(“Renewable Type”), and (2) a typical natural gas composition having ahigh level of CO₂ (“Natural Gas Type”). These gaseous mixtures (combinedfeeds), and the synthesis gas products obtained from these feeds, aresummarized in Table 1 below.

TABLE 1 Renewable Renewable Natural Natural gas Type Type Gas Type TypeCombined Synthesis Combined Synthesis Feed Gas Product Feed Gas Productmethane, mol-% 11.7 0.3 21.7 79 ethane, mol-% 5.8 0 5.8 0 propane, mol-%5.8 0 1.4 0 CO₂, mol-% 23.4 10.6 29.0 8.2 water, mol-% 53.3 12.7 42.18.6 H₂, mol-% 51.3 51.9 CO, mol-% 25.1 30.4 % methane 96 93 conversion %ethane 100 100 conversion % propane 100 100 conversion molar H₂:CO 2.051.71 ratio

From these results, it can be seen that the CO₂-steam reforming catalystand process can provide a synthesis gas product having a molar ratiothat is nearly 2:1 and therefore suitable for subsequent, directprocessing via the Fischer-Tropsch reaction, or at least without a prior(upstream) adjustment of this ratio. Whereas these favorable resultswere obtained at only 760° C. (1400° F.) reaction temperature, lowertemperatures, such as 704° C. (1300° F.) are also possible, in view ofthe high activity of the catalyst. Lower operating temperaturesdirectionally reduce the rate of side reactions that form coke, whichdeactivates the catalyst. FIG. 2 illustrates the relationship betweentemperature and methane conversion for feeds and catalysts of the typetested in Example 1, and in particular this figure illustrates theability to achieve greater than 85% methane conversion at 704° C. (1300°F.) and greater than 95% methane conversion at 760° C. (1400° F.). FIG.3 illustrates how the molar H₂O:CO₂ ratio of the gaseous mixture, forfeeds and catalysts of the type tested in Example 1, influences themolar H₂:CO ratio of the synthesis gas product, at temperatures of both704° C. (1300° F.) and 760° C. (1400° F.). In view of the possibility toestablish relationships between these parameters for a given feed,catalyst, and set of operating conditions, the gaseous mixturecomposition can serve as a convenient control for achieving a targetsynthesis gas product composition.

EXAMPLE 2

Additional experiments were conducted in which a typical natural gascomposition as described in Example 1 was subjected to CO₂-steamreforming as also described in this example. However, the gaseousmixture or combined feed in this case was spiked with H₂S at aconcentration of 800 mol-ppm. Despite this high level of sulfurcontamination, it was found that the offset in methane conversion waseasily restored by increasing the catalyst bed temperature from 760° C.(1400° F.) to 788° C. (1450° F.). Furthermore, the catalyst surprisinglyexhibited long-term stability over 400 operating hours (hours on stream)at this temperature, as well as the WHSV and pressure as described abovewith respect to Example 1. This stability, achieved despite theconsiderable sulfur concentration, was surprising in view of the sulfursensitivity of conventional catalysts used for steam methane reforming.

EXAMPLE 3

The gaseous mixture described in Example 1 as the “Renewable Type” andhaving the composition provided in Table 1 was tested using the catalystand conditions as described in

Example 1, to evaluate performance of the system for CO₂-steam reformingover an extended period of operation. Long-term stability testingrevealed that the composition of the synthesis gas product obtained wasstable over 500 hours of operation under these constant conditions,demonstrating essentially no deactivation, over the extended operatingperiod, of the reforming catalyst. FIG. 4 illustrates the stablesynthesis gas product composition obtained over this operating period,with a high level of conversion of methane. FIG. 5 illustrates thestable molar H₂/CO ratio of the synthesis gas product obtained, whichwas nearly a ratio of 2 and therefore ideal for use in a downstream FTsynthesis reaction to produce liquid hydrocarbons.

Overall, aspects of the invention relate to the use of dry reforming orCO₂-steam reforming to achieve high conversion of methane and/or otherhydrocarbon(s) and produce a synthesis gas product having desiredcharacteristics, including molar H₂:CO ratios as described herein.Further aspects relate to such reforming processes that use an activecatalyst with the ability to convert methane and/or other hydrocarbon(s)in the presence of CO₂, or both CO₂ and H₂O, with little coke depositionand high catalyst stability, even in the case of feeds comprisingsulfur-bearing contaminants and/or reactive compounds such as aromaticand/or olefinic hydrocarbons, with such contaminants and compounds beingassociated with rapid deactivation in conventional catalyst systems. Yetfurther aspects relate to such reforming processes that also provide astraightforward approach for direct use with further processing stages,such as Fischer-Tropsch synthesis for the production of liquid (C₄ ⁺)hydrocarbons and/or alcohols, alcohol synthesis via fermentation, orhydrogen production. Advantageously, the processes can utilize existingCO₂ present in sources of both renewable and non-renewable methane,preferably without the removal of this CO₂, and/or can utilize lowerlevels of water compared to conventional steam reforming of methane. Inaddition, the sulfur tolerance of the catalyst is further evidenced byits activity for converting sulfur-bearing contaminants into SO₂ and H₂Sthat are easily managed downstream, if necessary, using a single acidgas removal step. Those having skill in the art, with the knowledgegained from the present disclosure, will recognize that various changescan be made to these processes in attaining these and other advantages,without departing from the scope of the present disclosure. As such, itshould be understood that the features of the disclosure are susceptibleto modifications and/or substitutions without departing from the scopeof this disclosure. The specific embodiments illustrated and describedherein are for illustrative purposes only, and not limiting of theinvention as set forth in the appended claims.

1. A process for producing a synthesis gas product, the processcomprising contacting a gaseous mixture comprising a hydrocarbon and CO₂with a catalyst comprising a noble metal on a solid support comprisingcerium oxide.
 2. The process of claim 1, wherein the noble metal isselected from the group consisting of Pt, Rh, Ru, Pd, Ag, Os, Ir, andAu.
 3. The process of claim 2, wherein the catalyst comprises at leasttwo noble metals selected from the group consisting of Pt, Rh, Ru, Pd,Ag, Os, Ir, and Au.
 4. The process of claim 1, wherein the cerium oxideis present in an amount of at least about 95% by weight of the solidsupport.
 5. The process of claim 3, wherein the at least two noblemetals are Pt and Rh.
 6. The process of claim 5, wherein the Pt ispresent in an amount from about 0.05% to about 5% by weight of thecatalyst.
 7. The process of claim 5, wherein the Rh is present in anamount from about 0.05% to about 5% by weight of the catalyst.
 8. Theprocess of claim 1, wherein the gaseous mixture further comprises H₂O.9. The process of claim 1, wherein the gaseous mixture is obtained bycombining a hydrocarbon-containing feedstock and a CO₂-containingoxidant.
 10. The process of claim 9, wherein the gaseous mixturecomprises at least about 100 mol-ppm of total sulfur.
 11. The process ofclaim 9, wherein the gaseous mixture comprises aromatic and olefinichydrocarbons in a combined amount from about 1 mol-% to about 25 mol-%.12. The process of claim 9, wherein the hydrocarbon-containing feedstockis a methane-containing feedstock comprising natural gas or methane froma renewable methane source.
 13. The process of claim 9, wherein thegaseous mixture is obtained by further combining an H₂O-containingoxidant with the hydrocarbon-containing feedstock and the CO₂-containingoxidant.
 14. The process of claim 1, wherein the contacting is performedby flowing the gaseous mixture through a reactor vessel containing thecatalyst, at a weight hourly space velocity (WHSV) from about 0.1 hr⁻¹to about 2.5 hr⁻¹, to provide the synthesis gas product as an effluentfrom the reactor.
 15. The process of claim 1, wherein the contacting isperformed under reforming conditions including a temperature from about649° C. (1200° F.) to about 816° C. (1500° F.).
 16. The process of claim15, wherein the reforming conditions further include a gauge pressurefrom about 0 kPa to about 517 kPa (75 psig).
 17. The process of claim 1,wherein the hydrocarbon is methane and a conversion of the methane isleast about 85% at a temperature of at most about 704° C. (1300° F.).18. The process of claim 1, wherein the synthesis gas product comprisesH₂ in an amount representing at least about 70% of hydrogen inhydrogen-containing compounds in the gaseous mixture.
 19. A CO₂-steamreforming process comprising contacting a gaseous mixture comprising oneor more hydrocarbons, CO₂, and H₂O with a catalyst to produce a streamof a synthesis gas product having a molar H₂:CO ratio from about 1.5:1to about 2.3:1, wherein the process includes a rate of carbon formationthat is less than a baseline rate of carbon formation of a baselineprocess, in which the H₂O of the gaseous mixture is replaced with anequimolar amount of oxygen as CO₂.
 20. The process of claim 19, whereinthe catalyst comprises a solid support comprising cerium oxide andhaving Pt and Rh deposited thereon, each in an amount from about 0.05%to about 5% by weight of the catalyst.
 21. The process of claim 19,wherein the molar H₂:CO ratio, and a conversion of the one or morehydrocarbons of at least about 85%, are maintained for at least about500 hours of operation.
 22. The process of claim 19, wherein the one ormore hydrocarbons include methane.
 23. A CO₂-steam reforming and steamreforming process comprising contacting a stream of a gaseous mixturecomprising one or more hydrocarbons, CO₂, and H₂O with a catalyst toproduce a stream of a synthesis gas product, the process furthercomprising: determining a molar H₂:CO ratio of the synthesis gas productand, based on the molar H₂:CO ratio, adjusting a molar H₂O:CO₂ ratio ofthe gaseous mixture toward a target molar H₂:CO ratio of the synthesisgas product.
 24. The process of claim 23, wherein the contacting of theflowing stream of the gaseous mixture and catalyst is carried out underreforming conditions that include a temperature from about 649° C.(1200° F.) to about 760° C. (1400° F.).
 25. The process of claim 23,wherein the one or more hydrocarbons include methane.